Oil is typically recovered from individual wells, including wells which are pumped with a downhole pump powered by a rod string. Problems with conventional technology for recovering subsurface hydrocarbons include lenticular pay zones which are relatively small and heterogeneous, and situations where reservoir quality in adjacent sand lenses targeted for a single frac stage vary considerably. Pressure depletion may be higher in one zone, and fracture stimulation methodologies may be inefficient and largely ineffective because frac stages targeting multiple lenses may travel in a single interval with the highest depletion and lowest fracture gradient. Even in situations where the reservoir quality and pressure in adjacent sand lenses targeted for a single frac stage are similar, current methods may yield limited fracture half-lengths in a single zone and leave many zones under-stimulated due to constraints in pump rate and fluid viscosity to avoid excess frac height growth. Petrophysical evaluation of log analysis varies considerably due to variations in lithology, variable and extremely low water salinities, and unknown fluid invasion profiles. Many wells encounter thin production sand stingers with an average thickness of from 5 to 20 feet, in which case it is not practical to complete all of the zones due to the need for fracture stimulation. Many thin zones are deemed too marginal to perforate and stimulate.
Wells must be substantially vertical if beam pump lift systems are used, so that field areas with difficult access roads and location issues cannot be economically exploited. Moreover, there is no effective way to test oil and water productivity per zone while producing with a beam pump lift system. Paraffin deposition is problematic during the production phase, and there is a need to reduce development and lifting costs for effective production. Offshore or land development where surface constraints do not allow a high density of well development are not practical due to the need for a dedicated beam pump artificial lift system. Significant completion times are required for swab testing and fracture simulation using jointed tubing. Frac treatments can also be problematic on initial completion because rock properties of sand and shales are similar.
Various techniques have been employed for increasing the recovery of oil and other subterranean fluids utilizing a cooperative arrangement between wells. In some applications, water, natural gas, nitrogen, carbon dioxide, steam or another fluid may be injected in one well so that oil is driven toward a production well spaced from the first well. In cases where secondary water injection augments the gas drive mechanism, high volume artificial lift systems are commonly employed in the production phase. Solution gas drive is the typical primary drive mechanism in such relatively small, compartmentalized reservoirs. Secondary recovery with water injection from one well and recovery from another well for pressure maintenance and sweep generally are inefficient due to variabilities of rock properties and unknown continuity of sand lenses between wells. Injection of water in offset wells targeting specific zones for pressure maintenance and oil sweep generally do not allow the operator to know if injected water has experienced premature breakthrough in the production zone, since all zones are commingled and only total water and water rates are measured.
In other applications, a single well is drilled from the surface, and multiple horizontal or lateral wells extend from the vertical well to maximize the recovery of oil from the well. Various problems nevertheless exist with respect to prior art approaches for utilizing existing technology to recover formation fluids. Holes are conventionally drilled, logged, and tested to identify sand stingers for completion. Pay zones may be also selected in part based upon geologic mapping, cross sections, and both petrophysical and fluid analysis. Generally, a production casing is set with cement to cover the entire sand or shale zone, and all zones to be tested are perforated or fraced with a casing gun. The use of production tubing with suitable bridge plugs or packer assemblies to isolate specific zones for swab testing involves expensive rig time. Many times, cement, water, or gas zones must be squeezed, and the sand in the wellbore must be cleaned out and a swab test again performed, which is also rig time intensive and costly. Further rig time is used to fracture or stimulate a single zone or groups of stingers using multiple frac stages. Cement zones are typically squeezed of excess water if the zone significantly reduces production from other wells. Large beam pumps are typically used for artificial lift to pump the oil to the surface, and wells typically are worked over with operations involving swab tests, squeeze cementing, or recompleting operations. The inability to test production influx from specific zones during the production mode is also a problem, since all zones are typically commingled and produced with beam pump lift systems. Paraffin deposition on rods and tubing in production wells is a significant problem since produced oil moves slowly toward the surface, and is cooled as it travels upward in the well. High operating costs thus result from prior art techniques and equipment to recover subterranean formation fluids.
A number of challenges are commonly encountered when using a current exploitation approach, including:                Significant completion times are required for swab testing and fracture simulation using jointed tubing.        Lenticular pay zones are often relatively small in size with heterogeneous rock properties and thus require companies developing such reserves to drill wells on very small well spacings. High well densities are often required to exploit the multitude of relatively small sand lenses or reservoir compartments which may be very costly. When viewed in aggregate, the multiple stacked reservoirs may contain significant oil in place, but when only a single reservoir compartment is completed for production, the development may be uneconomic. Offshore or land development where surface constraints do not allow a high density of well development are not practical due to the need for a dedicated beam pump artificial lift system.        Many wells encounter thin production sand stingers with an average thickness of from 5 to 20 feet, in which case it is not practical to complete all of the zones due to the need for fracture stimulation. Many thin zones are deemed too marginal to perforate and stimulate using current completion practices.        In situations where reservoir quality in adjacent sand lenses targeted for a single fracture stimulation stage vary considerably or where pressure depletion is higher in one zone, current fracture stimulation methodologies may be inefficient and largely ineffective because fracture stages targeting multiple lenses will go in the single interval with the highest depletion/lowest fracture gradient.        In situations where the reservoir quality and pressure in adjacent sand lenses targeted for a single fracture stage are similar, current stimulation methods may yield limited fracture half-lengths in a single zone and leaves many zones under-stimulated due mainly to constraints in pump rate and fluid viscosity to avoid excessive fracture height growth.        Secondary recovery with water, gas, and/or steam injection from one well and recovery from another well for pressure maintenance and sweep generally are inefficient due to: (1) variability of rock properties, and (2) unknown continuity of sand lenses between wells.        Petrophysical evaluation through log analysis is complicated due to: (1) variations in lithology, (2) variable and extremely low water salinities, and (3) unknown fluid invasion profiles.        Many thin zones will be deemed too marginal to perforate and stimulate due to the relatively high cost of completion.        Wells must be substantially vertical if beam pump lift systems are used, thus field areas with difficult access road and location issues or in many offshore environments cannot be economically exploited.        Currently available methods do not allow one to test oil and water productivity per zone while producing the commingled sand/shale sequences with beam pump lift systems. Injection of water, steam, and/or gases in offset wells targeting specific zones for pressure maintenance and oil sweep generally do not allow the operator to know if injected water has experienced premature breakthrough in the completed zone of the production wells, since all zones are commingled and only total water and total hydrocarbon rates are measured. Current completion and production approaches in these oilfield development situations require expensive and time consuming rig intervention using a swab testing procedure in an attempt to ascertain which zones yield excessive water, steam, and/or gas.        In many oilfields, paraffin deposition inside the production tubing and on the exterior of rod strings in production wells is problematic during production phase. As the crude oil moves relatively slowly up the tubing string towards the surface, the oil cools which contributes significantly to the problem. Removing such paraffin from downhole tubing and rod strings is a costly problem in many such oilfield developments.        Paraffin deposition on rods and tubing in production wells is a significant problem since produced oil moves slowly toward the surface, and is cooled as it travels upward in the well.        
In other exploitation approaches, a single well is drilled from the surface, and multiple horizontal or lateral wells extend from the vertical well to maximize the recovery of oil from the well. Various problems nevertheless exist with respect to prior art approaches for utilizing existing technology to recover formation fluids. High operating costs thus result from prior art techniques and equipment to recover subterranean formation fluids.
U.S. Pat. No. 5,074,360 discloses a substantially horizontal wellbore drilled to intercept a pre-existing substantially vertical wellbore. The horizontal wellbore may be drilled from the surface, and multiple horizontal wells may be drilled to intercept a common vertical well, or drilled from a common site to multiple vertical wells. U.S. Pat. No. 4,458,945 discloses a system which utilizes vertical access shafts which extend through the oil and gas bearing zone. A piping system is laid through horizontal tunnels which interconnect the production wells intercepting a plurality of drainage-type mine sites to a pump at the base of a vertical axis shaft, thereby pumping the collected oil and gas to the surface. The production wells extend from the horizontal tunnel upward to the production zone. U.S. Pat. No. 6,848,508 discloses an entry well extending from the surface toward a subterranean zone. Slant wells extend from the terminus of an entry wellbore to the subterranean zone, or may alternatively extend from any other suitable portion of entry. Where there are multiple subterranean zones at varying depths, slant wells may extend through the subterranean zone closest to the surface into and through the deepest subterranean zone. Articulated wellbores may extend from each slant well into each subterranean zone. U.S. Pat. No. 6,119,776 discloses a method of producing oil using vertically spaced horizontal well portions with fractures extending between these portions.
The disadvantages of the prior art are overcome by the present invention, and an improved system and method are hereinafter disclosed for producing fluids from a subterranean formation.